Thixotropic cement slurry and placement method to cure lost circulation

ABSTRACT

Embodiments of methods for reducing lost circulation in a wellbore comprise inserting a conduit comprising a first and second end and an outer diameter and an inner diameter into the wellbore, and pumping a thixotropic cement slurry, wherein the thixotropic cement slurry will increase in viscosity with no shear and decrease in viscosity with shear, and have a power law exponent value of less than or equal to 0.3 when the thixotropic cement slurry has a density of greater than 12.69 pounds per gallon, through the conduit into the wellbore, in which the thixotropic cement slurry comprises at least one cement, at least one viscosifier, mix water, and one or more than one strength accelerating additives. The method further comprises allowing the thixotropic cement slurry to harden in the wellbore to create a plug, removing the conduit from the wellbore, and reducing lost circulation via the plug in the wellbore.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser.No. 62/570,383 filed Oct. 10, 2017.

TECHNICAL FIELD

Embodiments of the present disclosure generally relate to naturalresource well drilling and, more specifically, to compositions andmethods for isolating a lost circulation zone of a wellbore.

BACKGROUND

Extracting subterranean fuel sources may require drilling a hole fromthe surface to the subterranean geological formation housing the fuel.Specialized drilling techniques and materials are utilized to form thebore hole and extract the fuels. Specialized materials utilized indrilling operations include materials for sealing the casing-casingannulus of the wellbore, which may be formulated for specific downholeconditions.

A wellbore is a hole that extends from the surface to a location belowthe surface to permit access to hydrocarbon-bearing subterraneanformations. The wellbore contains at least a portion of a fluid conduitthat links the interior of the wellbore to the surface. The fluidconduit connecting the interior of the wellbore to the surface maypermit access between equipment on the surface and the interior of thewellbore. The fluid conduit may be defined by one or more tubularstrings (for example, casings or tubings) inserted into the wellbore andsecured in the wellbore.

During drilling of a wellbore, cementing the wellbore, or both, lostcirculation zones may be encountered and may result in loss of drillingfluid or cementing compositions. In a lost circulation zone, thedrilling fluid or cement composition flows out of the wellbore and intothe surrounding subterranean formation. Lost circulation zones mayresult in increased cost of the well through increased material costs toreplace lost fluids and downtime to remediate the lost circulation zone.Lost circulation zones may be remediated by introducing a lostcirculation material into the lost circulation zone to seal off the lostcirculation zone to prevent further fluid loss.

During well construction operations, conventional cement compositionsand conventional placement methods used to isolate lost circulationzones often result in high fluid loss to the formation.

SUMMARY

Accordingly, there is a need for effective cement slurries and placementmethods to form a cement plug to remediate or isolate lost circulationduring well construction. This need is met by the combination of thepresent thixotropic cement slurry and the present placement method (alsocalled “pump and pull placement method” hereinafter) for the thixotropiccement slurry, in which the thixotropic cement slurry comprises at leastone cement, at least one viscosifier, mix water, and one or more thanone strength accelerating additives.

In accordance with one embodiment, a method of reducing lost circulationin a wellbore is provided. The method comprises inserting a conduitcomprising a first and second end and an outer diameter and an innerdiameter into the wellbore, and pumping a thixotropic cement slurrythrough the conduit into the wellbore. As used herein, “thixotropic”means the thixotropic cement slurry will increase in viscosity with noshear and decrease in viscosity with shear, and have a power lawexponent value of less than or equal to 0.3 when the thixotropic cementslurry has a density of greater than 12.69 pounds per gallon. Thethixotropic cement slurry comprises at least one cement, at least oneviscosifier, mix water, and one or more than one strength acceleratingadditives. The method further comprises allowing the thixotropic cementslurry to harden in the wellbore to create a plug, removing the conduitfrom the wellbore, and reducing lost circulation via the plug in thewellbore.

Without being limited by theory, these methods reduce the cement slurrycosts by reducing the number of plugging attempts necessary to isolatelosses in most wells, in turn allowing a value realization through lowerrig non-productive time when compared to traditional plugging attempts.This methodology works in both onshore and offshore environments. Thepump and pull enables the plug placement without excessive hydrostaticpressure and overbalance experienced with conventional methods.

Additional features and advantages of the described embodiments will beset forth in the detailed description which follows, and in part will bereadily apparent to those skilled in the art from that description orrecognized by practicing the described embodiments, including thedetailed description which follows as well as the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The embodiments set forth in the drawings are illustrative and exemplaryin nature and not intended to limit the subject matter defined by theclaims. The following detailed description of the illustrativeembodiments can be understood when read in conjunction with thefollowing drawings, where like structure is indicated with likereference numerals and in which:

FIGS. 1A-1D are schematic illustrations depicting the pump and pullmethod according to one or more embodiments of the present disclosure;and

FIG. 2 is a graphical illustration of the performance of the thixotropiccement slurry by plotting the temperature, pressure, consistency, andmotor speed versus time, according to one or more embodiments describedin this disclosure.

DETAILED DESCRIPTION

As used throughout this disclosure, the term “annulus” refers to a spacebetween two concentric or eccentric objects, such as between thewellbore and casing or between casing and tubing, where fluid can flow.

As used throughout this disclosure, the term “blow out preventer,” orBOP, refers to a large valve at the top of a well that may be closed ifthe drilling crew loses control of formation fluids. By closing thisvalve (usually operated remotely via hydraulic actuators), the drillingcrew usually regains control of the reservoir, and procedures can thenbe initiated to increase the mud density until it is possible to openthe BOP and retain pressure control of the formation. BOPs come in avariety of styles, sizes and pressure ratings. Some can effectivelyclose over an open wellbore, some are designed to seal around tubularcomponents in the well (drillpipe, casing or tubing) and others arefitted with hardened steel shearing surfaces that can actually cutthrough drillpipe. Since BOPs are critically important to the safety ofthe crew, the rig and the wellbore itself, BOPs are inspected, testedand refurbished at regular intervals determined by a combination of riskassessment, local practice, well type and legal requirements. BOP testsvary from daily function testing on critical wells to monthly or lessfrequent testing on wells thought to have low probability of wellcontrol problems.

As used throughout this disclosure, the term “borehole” refers to thewellbore itself, including the open hole or uncased portion of the well.Borehole may refer to the inside diameter of the wellbore wall, the rockface that bounds the drilled hole.

As used throughout this disclosure, the term “cementing head” refers toa device fitted to the top joint of a casing string allowing connectionof a fluid circulation line from non-rig equipment.

As used throughout this disclosure, the term “choke” refers to a deviceincorporating an orifice that is used to control fluid flow rate ordownstream system pressure. Chokes are available in severalconfigurations for both fixed and adjustable modes of operation.Adjustable chokes enable the fluid flow and pressure parameters to bechanged to suit process or production requirements. Fixed chokes do notprovide this flexibility, although they are more resistant to erosionunder prolonged operation or production of abrasive fluids.

As used throughout this disclosure, the term “choke line” refers to ahigh-pressure pipe leading from an outlet on the BOP stack to thebackpressure choke and associated manifold. During well-controloperations, the fluid under pressure in the wellbore flows out of thewell through the choke line to the choke, reducing the fluid pressure toatmospheric pressure. In floating offshore operations, the choke andkill lines exit the subsea BOP stack and then run along the outside ofthe drilling riser to the surface. The volumetric and frictional effectsof these long choke and kill lines must be considered to control thewell properly.

As used throughout this disclosure, the term “diverter” refers to aconduit installed on the conductor casing to release fluid from theannulus and to divert flow from rig personnel and equipment in case ofan unexpected influx of formation fluids during drilling.

As used throughout this disclosure, the term “drill string” refers tothe combination of the drillpipe, the bottomhole assembly and any othertools used to place the cement in the wellbore.

As used throughout this disclosure, the term “fluid” may includeliquids, gases, or both. As used throughout the disclosure, “spacerfluid” refers to a fluid utilized to space apart any two other materialsutilized in well production.

As used throughout this disclosure, the term “hydrocarbon-bearingformation” refers to a subterranean geologic region containinghydrocarbons, such as crude oil, hydrocarbon gases, or both, which maybe extracted from the subterranean geologic region.

As used throughout this disclosure, the term “kill line” refers to ahigh-pressure pipe leading from an outlet on the BOP stack to thehigh-pressure rig pumps. During normal well control operations, killweight fluid is pumped through the drillstring and annular fluid istaken out of the well through the choke line to the choke, which dropsthe fluid pressure to atmospheric pressure. If the drillpipe isinaccessible, it may be necessary to pump heavy drilling fluid in thetop of the well, wait for the fluid to fall under the force of gravity,and then remove fluid from the annulus. In such an operation, while onehigh pressure line would suffice, it is more convenient to have two. Inaddition, this provides a measure of redundancy for the operation. Infloating offshore operations, the choke and kill lines exit the subseaBOP stack and run along the outside of the riser to the surface. Thevolumetric and frictional effects of these long choke and kill linesmust be taken into account to properly control the well.

As used throughout this disclosure, the term “kill weight fluid” refersto a mud whose density is high enough to produce a hydrostatic pressureat the point of influx in a wellbore and shut off flow into the well.Kill weight mud, when needed, must be available quickly to avoid loss ofcontrol of the well or a blowout. Thus, it is usually made by weightingup some of the mud in the system or in storage by adding barite orhematite. Unless diluted in advance, the mud may become too thick andperhaps un-pumpable due to high solids loading. A weight-up pilot testcan identify if and how much dilution will be needed in advance ofadding weighting material to the mud in the pits.

As used throughout this disclosure, the term “liner” refers to a casingstring that does not extend to the top of the wellbore, but instead isanchored or suspended from inside the bottom of the previous casingstring.

As used throughout this disclosure, the term “mud weight” refers to themass per unit volume of a drilling fluid and is synonymous with muddensity. Mud weight controls hydrostatic pressure in a wellbore andprevents unwanted flow into the well. The weight of the mud alsoprevents collapse of the casing and the open hole. Excessive mud weightcan cause lost circulation by propagating, and then filling fractures inthe rock.

As used throughout this disclosure, the term “open hole” refers to theuncased portion of a well.

As used throughout this disclosure, the term “overbalanced” refers to awell wherein the hydrostatic pressure inside the open hole or casing orliner is greater than the reservoir pressure.

As used throughout this disclosure, the term “stand” refers to two orthree single joints of drillpipe or drill collars that remain screwedtogether during tripping operations.

As used throughout this disclosure, the term “top drive” refers to adevice that turns the drillstring. It consists of one or more motors(electric or hydraulic) connected with appropriate gearing to a shortsection of pipe called a quill, that in turn may be screwed into a saversub or the drillstring itself. The top drive is suspended from the hook,so the rotary mechanism is free to travel up and down the derrick.

As used throughout this disclosure, the term “trip” refers to the act ofpulling the drillstring out of the hole or replacing it in the hole. Apipe trip is usually done because the bit has dulled or has otherwiseceased to drill efficiently and must be replaced.

As used throughout this disclosure, the term “work string” is a genericterm used to describe a tubing string or conduit in a well.

As stared previously, embodiments of the present disclosure are directedto a thixotropic cement slurry and methods of reducing lost circulationin a wellbore by utilizing the thixotropic cement slurry. The methodcomprises inserting a conduit comprising a first and second end and anouter diameter and an inner diameter into the wellbore, and pumping athixotropic cement slurry through the conduit into the wellbore.

The thixotropic cement slurry comprises at least one cement, at leastone viscosifier, mix water, and one or more than one strengthaccelerating additives. The method further comprises allowing thethixotropic cement slurry to harden in the wellbore to create a plug,removing the conduit from the wellbore, and reducing lost circulationvia the plug in the wellbore.

The fluid conduit may be defined by a tubular string installed in thewellbore. The wellbore annulus has a volume defined between the externalsurface of the tubular string and the wellbore wall. As wellboredrilling continues and the wellbore extends deeper into the subterraneanformation, one or more additional tubular strings may be installedwithin the fluid conduit defined by the initial tubular string.Additional tubular strings may have outer cross-sectional dimensionsthat are less than the inner cross-sectional dimensions of the tubularstrings within which the additional tubular strings are disposed. Thus,the additional tubular string, when installed in the wellbore, may forma casing-casing annulus defined between the exterior surface of theadditional tubular string and the interior surface of the tubular stringsurrounding the additional tubular string. Therefore, after drilling iscomplete and the wellbore is fitted with production tubing forproduction, the wellbore may comprise a plurality of tubular strings ofprogressively smaller cross-sectional dimensions that form a wellboreannulus and a plurality of casing-casing annuli.

Without being limited by theory, the primary use of a thixotropic cementslurry is for lost circulation mitigation during the drilling phase ofwellbore construction. Lost circulation more commonly happens when theeffective density of a circulating fluid during drilling exceeds theformation fracture pressure at the given depth. The density selection ofthe thixotropic slurry is on a case-by-case basis for the wellboreoperating conditions. It is a function of the bottom hole pressure,temperature, mud weight, and loss rate.

The thixotropic cement slurry can be used for sealing the annulus orremediating a wellbore under a range of different downhole conditions inthe wellbore. For example, in some embodiments, the thixotropic cementslurry may be adapted to different downhole conditions by modifying thedensity, viscosity, curing time, or other properties of the thixotropiccement slurry.

A conventional plug cement slurry is not thixotropic and thus has a flowbehavior index of 1>n>0.3 for a cement with a density greater than 12.69ppg. A flow behavior index of less than 1 classifies a fluid aspseudo-plastic, and all cements will fall under this category. Bycomparison, the thixotropic cement slurry has a flow behavior index ofn≤0.3 for a cement with a density greater than 12.69 ppg.

The thixotropic cement slurry demonstrates thixotropic behavior whenplaced into the wellbore. Thixotropic behavior is characteristic offluidity during dynamic conditions (induced forces) and rapid gelstrength development when left static (no external forces). Aviscosifier provides a minimum viscosity of the interstitial waterwithin the matrix, stability to prevent settling, and primary componentfor thixotropic behavior. The strength accelerating additive may act asa secondary thixotropic modifier which complements the stability,improves the transition time (time from the liquid to gelled state), andcontrols the thickening time of the cement.

Various components for the cement, viscosifier, and strengthaccelerating additive are contemplated. The cement may include one ormore of Portland cements, alumina cements, blast furnace slag cementsand Pozzolanic cements. In a specific embodiment, the cement comprisesPortland cement. The viscosifier may include one or more ofhydroxyethylcellulose, carboxymethylcellulose, guar gum,hydroxypropylguar, xanthan gum, bentonite, hectorite and sepeolitebentonite. In a specific embodiment, the viscosifier comprisesbentonite. Various amounts are contemplated for the viscosifier. Forexample, the viscosifer may be added to the mix water withconcentrations ranging from 1 to 5% by weight of cement (BWOC)pre-hydrated.

The strength accelerating additive may comprise one or more of sodiumchloride, calcium chloride, triethanolamine, sodium silicate, sodiummetasilicate, and sodium aluminate. In a specific embodiment, thestrength accelerating additive comprises sodium metasilicate, and sodiumsilicate. While various amounts are considered suitable, the strengthaccelerating additive can be added to the mix water with concentrationsranging from 0.5 to 3% BWOC pre-hydrated or from 2 to 15 gallons perhundred sacks of cement (gphs). The thixotropic cement slurry may alsocomprise mix water selected from least one of fresh water, low saltwater, or seawater.

Due to the mix water quality, anti-foaming chemicals and dispersants maybe added to the thixotropic cement slurry to achieve the performanceproperties of the slurry design. Retarders may also be added to adjustthe thickening time. In some embodiments, the thixotropic cement slurrymay have a density of from 12.0-15.0 ppg.

The thixotropic cement slurry may have a thickening time sufficient toallow the thixotropic cement slurry to be transferred or otherwiseintroduced to the wellbore, remediation zone, or other region of thewellbore before the buildup of viscosity is sufficient to cause transferproblems, such as inability to pump the thixotropic cement slurry.

Moreover, the thixotropic cement slurry may be capable of withstanding awide range of temperatures and pressures. For example, the thixotropiccement slurry may be applicable in temperatures of from 4.4 degreesCelsius (° C.) to 121° C. The hardened thixotropic cement plug may becapable of withstanding pressures of up to 10,000 pounds of force persquare inch (psi) (1 psi equals 6.895 kilopascals (kPa)).

The rheology and density of the thixotropic cement slurry can beadjusted over a wide range of values depending on the requirement forthe well and the downhole conditions of the well. The final density ofthe thixotropic cement slurry may depend on the geology of thesubterranean formation in the zone being sealed. The thixotropic cementslurry may have a density sufficient to enable the thixotropic cementslurry to exert hydrostatic pressure on the wellbore wall or interiorsurface of an outer casing to support the wellbore.

The thixotropic cement slurry may have a gel strength at bottom holecirculating temperature (BHCT) that is sufficient to maintain thepump-ability of the thixotropic cement slurry to prevent stuck-pipeproblems. The gel strength refers to the shear stress of a fluidmeasured at a low shear rate following a defined period of time duringwhich the fluid is maintained in a static state. In some embodiments,the gel strength of the slurry at 10 minutes may be greater than twotimes the gel strength of the slurry at 10 seconds. The 10-second gelstrength and 10-minute gel strength may be measured according to thetest methods subsequently described in this disclosure. The thixotropiccement slurry may have a shear stress of greater than 9 centipoise at 3rotations per minute at bottom hole circulating temperature.

In further embodiments, the spacer fluid used in combination with thethixotropic cement slurry in the pump and pull method is an unweightedfluid modified for compatibility between both the wellbore fluid type(water based, oil based, synthetic based) and thixotropic cement slurry.The composition can be fresh water, sea water, or the primary componentof the base oil with a surfactant package to ensure water wetting. Thevolumes of the spacer fluid can range from 50 to 400 barrels (bbl)depending on the severity of losses, wellbore fluid density, cementdensity and bottom hole conditions.

The pump and pull placement method is a placement technique to optimizethe success of the hardened thixotropic cement slurry plug curing thelosses in the wellbore. This method utilizes a spacer fluid incombination with the thixotropic cement slurry. It can be executedthrough the drilling bottom hole assembly or work string andincorporates manipulation of the top drive and diverter or blow outpreventer. There are specific calculations that are required to ensurethe plug placement success using the pump and pull method. This methodworks for all wellbore trajectories including vertical, deviated, andhorizontal.

The conventional placement method includes a conduit placed at a fixeddepth in the wellbore, through which a spacer fluid and cement is pumpedinto the annulus. These fluids are displaced by a trailing spacer anddisplacement fluid. The conduit does not move throughout the placementand the placement is complete when the fluid levels inside and outsidethe conduit are at the balance point. Without being limited to examples,the pump and pull placement method may be executed in exemplaryembodiment as follows:

-   -   1. Position end of work string at a specified depth at or above        loss zone, as schematically depicted in FIG. 1A.    -   2. Ensure surface blow out preventer lines up to take returns        through the choke and/or kill line or diverter, then close        annular rams.    -   3. Pump a given volume of linear spacer fluid at a given rate=.    -   4. Spot Pvac of selected density thixotropic cement at a given        rate, as schematically depicted in FIG. 1B.    -   5. Pump a given volume of linear spacer fluid at a given rate.    -   6. Pump calculated volume of wellbore fluid to displace until        30% of Pvac have exited the work string.    -   7. Stop pumping.    -   8. Open annular rams. Close diverter or choke and/or kill lines.    -   9. Simultaneously break the cementing stand off and connect Top        Drive to work string.    -   10. Resume displacement with rig at Qpnp while pulling stands 15        feet/minute as schematically depicted in FIG. 1C.    -   11. Pull each stand, break connection, rack back, then reconnect        top drive on rig floor    -   12. Repeat for Spnp-s stands.    -   13. Pull out of hole five additional stands and wait on cement        to achieve a given compressive strength as schematically        depicted in FIG. 1D.

The calculations for the pump and pull placement method begin withselecting the appropriate work string size proportionate to the openhole size. The open hole size can vary from 6⅝″ to 2⅞″. In oneembodiment, the work string selection focuses on a 2.25 ratio of thelikely open hole size (including washout) to work string across thecement plug, where work string size rounded up to the maximum workstring size available.

$W_{sod} = \frac{{OH}_{eq}}{2.25}$

Where:

W_(sod)=size of the work string outside diameter, inches (″)

OH_(eq)=equivalent open hole size, (″)

Then the plug volume inside the selected work string, from surface tothe ending depth of the work string for the plug placement iscalculated.

$W_{sv} = {\left\lbrack {\left\lbrack \frac{\left( W_{sid} \right)^{2}}{1029.45} \right\rbrack*\left( {W_{std} - W_{srkb}} \right)} \right\rbrack - 5}$

Where:

W_(sv)=volume of the work string, bbl

W_(sid)=inside diameter of the work string, (″)

W_(std)=depth of the work string at total depth, feet (ft)

W_(srkb)=depth of the work string at surface, ft

The work string volume may be divided by a factor of 0.7 to get themaximum volume of cement plug possible.

$P_{vmax} = \frac{W_{sv}}{0.70}$

Where:

P_(vmax)=maximum plug volume that can be performed, bbl

From this known maximum volume, the actual volume planned in the openhole is determined—usually a function of length.

The next series of calculations are the pump rate. These calculationsare based on the annular capacity of the likely open hole size includingwashout to work string across the cement plug (i.e. 14″ OH equivalent to5.5″ work string).

$C_{ann} = \left\lbrack \frac{\left( {OH}_{eq} \right)^{2} - \left( W_{sod} \right)^{2}}{1029.45} \right\rbrack$

Where:

C_(ann)=annular capacity of the equivalent open hole and work string,bbl per ft.

With the annular capacity, the optimum pump and pull rate of 15 ft perminute helps determine the surface pump rate. This is the quotient of 15ft per minute and the annular capacity in bbl per minute.

Where:

Q _(pnp) ==C _(ann)*15 feet per minute

Q_(pmp)=pump and pull displacement rate, bbl per minute

The last part of the calculations is to determine how many 90 footstands, or three consecutive joints of drillpipe, need pulling tocomplete the placement and ensure the work string has cleared the cementin the borehole. In specific embodiments, 70% of the total plug volumemay be the volume left in the work string before starting the pump andpull technique. This determines the volume of cement and the resultinglength inside the work string.

P _(vtp) =P _(vac)*0.70

Where:

P_(vac)=actual total plug volume required from planned length inborehole, bbl

P_(vip)=volume of total plug volume left inside the work string, bbl

Then the volume pumped during the pumping and pulling of a 90-foot standis determined by multiplying 90 ft by the pump rate divided by the pullrate.

$P_{vpmp} = {\left( \frac{90\mspace{14mu} {feet}}{15\mspace{14mu} {feet}\mspace{14mu} {per}\mspace{14mu} {minute}} \right)*Q_{pnp}}$

Where:

P_(vpmp)=volume of cement displaced during pulling of one 90-foot stand,bbl

This volume uses the following relationship with the Pvip to identifythe number of stands to pull.

$S_{pmp} = \left( \frac{P_{vip}}{P_{vpnp}} \right)$

Where:

S_(pnp)=minimum 90-foot stands to be pulled, stands

Add a safety factor of 2 stands to conclude the total number of pulled90-foot stands to set the plug in place.

S _(pmp-s) =S _(pmp)+2

Where:

S_(pnp-s)=minimum 90-foot stands to be pulled with safety factor, stands

In some embodiments, the method may further include letting the slurryharden, for example, for at least 3 hours. In some embodiments, thespacer fluid and the thixotropic cement slurry may be introduced to thewellbore through the drill string.

Additionally, in some embodiments, the method may include determiningthe volume and densities of the spacer fluid. The method may furtherinclude determining the density, volume, or both of the thixotropiccement slurry to be pumped to isolate the weak zones.

In some embodiments, the drill string inner diameters can range from5.875″ to 2.441″. In some embodiments, the drill string can havevariable inner and outer diameters that change along the length of thepipe. In some embodiments, the drill string can bend or deform as it issubjected to higher pressures and temperatures.

In some embodiments, the size of the open hole can range from 36″ to5⅞″.

Once the thixotropic cement slurry has cured into a solid plug, drillingthe wellbore may re-commence. In some embodiments, the drill string anddrill bit may be used to drill through at least a portion of the plug tocontinue drilling the wellbore.

Test Methods

The gel strength refers to the shear stress of the thixotropic cementslurry measured at a low shear rate following a defined period of timeduring which the thixotropic cement slurry is maintained in a staticstate. The shear stress of the thixotropic cement slurry at low shearrate may be measured using a standard oilfield rotational viscometeroperated a low rotor speed, typically 3 rpm, according to the testmethods described in API Recommended Practice On Testing Well Cements(RP 10B-2).

EXAMPLES

The following examples illustrate one or more features of the presentdisclosure. It should be understood that these examples are not intendedto limit the scope of the disclosure or the appended claims in anymanner.

Example 1: Example Pump and Pull Method

Another embodiment of the pump and pull method in an overbalanced wellis described as follows:

-   -   1. Open choke and kill lines.        -   Manipulation of the blow out preventer (BOP) to divert the            well annular flow path of the fluids towards orifices that            have a smaller cross sectional area for flow. This            contributes to controlling the free fall effect by applying            back pressure if and when circulation is regained during the            cement placement using the pump and pull method.    -   2. Close Annular.        -   Closing the conventional well annular flow path which is            considered an open annulus with no restrictions to flow.    -   3. Pump 350 bbl drill water ahead at 4 bpm.        -   This is a calculated volume to reduce the hydrostatics            across the loss zone during and after cement placement. This            is an important step in the methodology. The formation sees            a column full of water down the work string and believes the            hydrostatics are being reduced to its balance point. Here it            works to divert the flow up the annulus rather than into the            loss zone. This usually helps contribute to regaining            circulation enough the enable the cement slurry to be placed            into the wellbore versus into the loss zone.    -   4. Pump 100 bbl of 112 pcf cement at 4 bpm.        -   This is a calculated volume for the cement plug as a            function of the equivalent open hole size. What is also            important is that of this volume, 30% will be pumped outside            the work string prior to commencing pump and pull            operations. The remaining volume will be placed, in layers            like stacking pancakes, on top of this volume. This is how            the pump and pull works. It reduces the hydrostatics the            loss zone experiences while stacking up the cement in            different layers to build up the plug. Conventionally you            are continuously pressure pumping the cement plug in place            which is feeding the loss zone and essentially pumping away            to the loss zone. Pump and pull methods works to prevent            this.    -   5. Pump a calculated amount of drill water behind to balance        (about 50 bbl) at 4 bpm.        -   This is the same linear fluid used in the spacer fluid ahead            but enough volume to balance and ensure the hydrostatic            pressure transmitted at the end of the job is at or below            the loss zone. This volume changes depending on actual well            operations and conditions.    -   6. Pump a calculated amount of 68 pcf mud weight to complete        displacement at 4 bpm.        -   The volume of mud behind is part of the balance calculations            noted above. It is the last fluid pumped into the well            before the pump and pull operations begin. The volume is            also changing depending on actual well operations and            conditions.    -   7. When 30 bbl has exited the work string, shut down.    -   8. Open annular, close choke and kill lines.        -   It is not advised to perform pulling operations on the            conduit while having the annulus closed. This is referred to            as “stripped” and only advised for well control pumping. The            next step is to open the annulus and close the restricted            flow paths.    -   9. Simultaneously break cementing stand off and tie-in top        drive.        -   Rig down the cementing head and connections used to place            the cement and rig up the top drive to the work string as            the rig will pump the mud into the work string while pulling            the work string out of the wellbore.    -   10. Simultaneously resume displacement at 2 bpm while pulling        stands at 17 feet per minute.        -   This step is a result of the balance calculation to match            the pump rate with the pull rate. It assumes a fixed volume            of the cement is in the annulus. From this it adds the            layers into the existing plug stacking it higher in the hole            further isolating the loss zone.    -   11. Continue until clearing top of cement by 2 stands.        -   This is a safety measure to ensure all of the cement is            below the work string and is clear.    -   12. Pick up 5 stands then reverse out 1 annular volume (˜700        bbl).        -   This is a safety measure to ensure all of the cement is            below the work string and nothing will be found in the            annulus.    -   13. Shut in backside and monitor pressure.

Example 2: Comparative Data

A cement slurry was tested for thickening time and fluid loss in orderto evaluate the performance of cement slurry. The cement slurry includedPortland cement, 2% BWOC bentonite, and 1% BWOC sodium metasilicate, and0.38% BWOC retarder. The cement slurry had a density of 13.5 ppg and aslurry yield of 1.71 ft³/sks.

FIG. 2 shows the thickening time test of a thixotropic cement at 101pounds per cubic feet (pcf) (13.5 pounds per gallon (ppg)) tested on anAPI modified schedule. The results of this thickening time test areprovided in Table 1.

TABLE 1 Thixotropic cement slurry thickening time: Thickening timeConsistency Time 102 Bearden units of consistency (Bc) 3:34 hrs

The compositions of the conventional cement slurry and the thixotropiccement slurry are compared in Table 2.

TABLE 2 Cement slurry compositions: Conventional Thixotropic CementSlurry Cement Slurry Density (ppg) 12.7-15.0 13.5 Cement (% BWOC) 100 100 Bentonite (% BWOC)  0-1.5 2 Sodium metasilicate (% BWOC) 0 1 Sodiumsilicate (gphs) 0 0 Retarder (% BWOC) 0 0.38 Flow behavior index, n 0.3< n < 1 n ≤ 0.3

Different slurries and different placement methods were tested togetheron the same well. The results of this test are shown in Table 3.

TABLE 3 Summary of cement plug events on the same well: Placement PlugNo. Slurry Type Method Result 1 Conventional Conventional No zonalisolation 2 Conventional Conventional No zonal isolation 3 ConventionalPump and Pull No zonal isolation 4 Thixotropic Pump and Pull Zonalisolation

Non-thixotropic plug numbers 1 and 2 were each pumped into the holeseparately and at different times and left to harden. When the rig ranpipe down the hole to find the top of the cement plug, the drillpipe didnot encounter any cement at the appropriate depth and there were noreturns to surface. Therefore, there was no zonal isolation.Non-thixotropic plug number 3 was placed in the hole using the pump andpull method instead of the conventional placement method. However, aswith plugs 1 and 2, the drillpipe did not encounter any cement at theappropriate depth and there were no returns to surface, so plug number 3also failed to demonstrate zonal isolation.

Plug number 4, composed of the thixotropic cement slurry, was pumpedinto the hole using the pump and pull placement method and left toharden. When the rig ran pipe down the hole to find the top of thecement plug, the drillpipe encountered plug number 4 at the appropriatedepth and with no dynamic fluid losses. The rig then circulated moredrilling mud downhole, flow checked the well, and determined that thewell was static. Therefore, the thixotropic cement slurry placed usingthe pump and pull method successfully created zonal isolation.

It is noted that one or more of the following claims utilize the term“where” or “in which” as a transitional phrase. For the purposes ofdefining the present technology, it is noted that this term isintroduced in the claims as an open-ended transitional phrase that isused to introduce a recitation of a series of characteristics of thestructure and should be interpreted in like manner as the more commonlyused open-ended preamble term “comprising.” For the purposes of definingthe present technology, the transitional phrase “consisting of” may beintroduced in the claims as a closed preamble term limiting the scope ofthe claims to the recited components or steps and any naturallyoccurring impurities. For the purposes of defining the presenttechnology, the transitional phrase “consisting essentially of” may beintroduced in the claims to limit the scope of one or more claims to therecited elements, components, materials, or method steps as well as anynon-recited elements, components, materials, or method steps that do notmaterially affect the novel characteristics of the claimed subjectmatter. The transitional phrases “consisting of” and “consistingessentially of” may be interpreted to be subsets of the open-endedtransitional phrases, such as “comprising” and “including,” such thatany use of an open ended phrase to introduce a recitation of a series ofelements, components, materials, or steps should be interpreted to alsodisclose recitation of the series of elements, components, materials, orsteps using the closed terms “consisting of” and “consisting essentiallyof.” For example, the recitation of a composition “comprising”components A, B, and C should be interpreted as also disclosing acomposition “consisting of” components A, B, and C as well as acomposition “consisting essentially of” components A, B, and C. Anyquantitative value expressed in the present application may beconsidered to include open-ended embodiments consistent with thetransitional phrases “comprising” or “including” as well as closed orpartially closed embodiments consistent with the transitional phrases“consisting of” and “consisting essentially of.”

As used in the Specification and appended Claims, the singular forms“a”, “an”, and “the” include plural references unless the contextclearly indicates otherwise. The verb “comprises” and its conjugatedforms should be interpreted as referring to elements, components orsteps in a non-exclusive manner. The referenced elements, components orsteps may be present, utilized or combined with other elements,components or steps not expressly referenced.

It should be understood that any two quantitative values assigned to aproperty may constitute a range of that property, and all combinationsof ranges formed from all stated quantitative values of a given propertyare contemplated in this disclosure. The subject matter of the presentdisclosure has been described in detail and by reference to specificembodiments. It should be understood that any detailed description of acomponent or feature of an embodiment does not necessarily imply thatthe component or feature is essential to the particular embodiment or toany other embodiment. Further, it should be apparent to those skilled inthe art that various modifications and variations can be made to thedescribed embodiments without departing from the spirit and scope of theclaimed subject matter.

The presently described subject matter may include one or more aspects,which should not be regarded as limiting on the teachings of the presentdisclosure. A first aspect may include a method of reducing lostcirculation in a wellbore comprising: inserting a conduit comprising afirst and second end and an outer diameter and an inner diameter intothe wellbore; pumping a thixotropic cement slurry, wherein thethixotropic cement slurry will increase in viscosity with no shear anddecrease in viscosity with shear, and have a power law exponent value ofless than or equal to 0.3 when the thixotropic cement slurry has adensity of greater than 12.69 pounds per gallon, through the conduitinto the wellbore, in which the thixotropic cement slurry comprises atleast one cement, at least one viscosifier, mix water, and one or morethan one strength accelerating additives; allowing the thixotropiccement slurry to harden in the wellbore to create a plug; removing theconduit from the wellbore; and reducing lost circulation via the plug inthe wellbore.

Another aspect includes any of the previous aspects, in which theconduit is a pipe and the inner diameter has a range of 2.551″ to5.875″.

Another aspect includes any of the previous aspects, in which the cementcomprises Portland cement.

Another aspect includes any of the previous aspects, in which theviscosifier comprises bentonite.

Another aspect includes any of the previous aspects, in which thestrength accelerating additive comprises at least one of sodium silicateor sodium metasilicate.

Another aspect includes any of the previous aspects, in which thethixotropic cement slurry further comprises at least one dispersant, atleast one antifoaming agent, or at least one retarder.

Another aspect includes any of the previous aspects, in which thethixotropic cement slurry has a shear stress of greater than 9centipoise at 3 rotations per minute at bottom hole circulatingtemperature.

Another aspect includes any of the previous aspects, in which the gelstrength of the thixotropic cement slurry at bottom hole circulatingtemperature at 10 minutes is greater than twice the gel strength of theslurry at 10 seconds.

Another aspect includes any of the previous aspects, in which thethixotropic cement slurry mix water comprises at least one of freshwater, low salt water, or seawater.

Another aspect includes any of the previous aspects, in which thethixotropic cement slurry comprises bentonite ranging from 1 weightpercent to 5 weight percent of cement pre-hydrated.

Another aspect includes any of the previous aspects, in which thethixotropic cement slurry comprises sodium meta-silicate ranging from0.5 weight percent to 3 weight percent of cement pre-hydrated.

Another aspect includes any of the previous aspects, in which the plughas a maximum volume calculated by dividing a volume of the conduit by afactor of 0.7.

Another aspect includes any of the previous aspects, in which the outerdiameter of the conduit is equal to a diameter of the wellbore dividedby 2.25.

Another aspect includes any of the previous aspects, in which thediameters of the conduit vary along a length of the conduit.

Another aspect includes any of the previous aspects, in which theconduit may bend at high pressure and high temperature.

Another aspect includes any of the previous aspects, in which theconduit is inserted to a specified depth at or above a loss zone.

Another aspect includes any of the previous aspects, in which a spacerfluid is pumped through the conduit prior to pumping the thixotropiccement slurry.

Another aspect includes any of the previous aspects, in which the spacerfluid is pumped into the conduit following the thixotropic cementslurry.

Another aspect includes any of the previous aspects, in which pumpingthe thixotropic cement slurry through the conduit is followed by pumpinga drilling mud through the conduit.

Another aspect includes any of the previous aspects, in which theconduit is removed while pumping one of the thixotropic cement slurry,the drilling mud, or the spacer fluid through the conduit until thesecond end of the conduit is above the plug.

Another aspect includes any of the previous aspects, in which thedrilling mud pumps down the wellbore outside the conduit and then flowsup the conduit.

What is claimed is:
 1. A method of reducing lost circulation in awellbore comprising: inserting a conduit comprising a first and secondend and an outer diameter and an inner diameter into the wellbore;pumping a thixotropic cement slurry, wherein the thixotropic cementslurry will increase in viscosity with no shear and decrease inviscosity with shear, and have a power law exponent value of less thanor equal to 0.3 when the thixotropic cement slurry has a density ofgreater than 12.69 pounds per gallon, through the conduit into thewellbore, in which the thixotropic cement slurry comprises at least onecement, at least one viscosifier, mix water, and one or more than onestrength accelerating additives; allowing the thixotropic cement slurryto harden in the wellbore to create a plug; removing the conduit fromthe wellbore; and reducing lost circulation via the plug in thewellbore.
 2. The method of claim 1, in which the conduit is a pipe andthe inner diameter has a range of 2.551″ to 5.875″.
 3. The method ofclaim 1, in which the cement comprises Portland cement.
 4. The method ofclaim 1, in which the viscosifier comprises bentonite.
 5. The method ofclaim 1, in which the strength accelerating additive comprises at leastone of sodium silicate or sodium metasilicate.
 6. The method of claim 1,in which the thixotropic cement slurry further comprises at least onedispersant, at least one antifoaming agent, or at least one retarder. 7.The method of claim 1, in which the thixotropic cement slurry has ashear stress of greater than 9 centipoise at 3 rotations per minute atbottom hole circulating temperature.
 8. The method of claim 1, in whichthe thixotropic cement slurry has a gel strength at 10 minutes at bottomhole circulating temperature greater than twice the gel strength at 10seconds at bottom hole circulating temperature.
 9. The method of claim1, in which the thixotropic cement slurry mix water comprises at leastone of fresh water or seawater.
 10. The method of claim 1, in which thethixotropic cement slurry comprises bentonite in an amount ranging from1 weight percent to 5 weight percent of cement pre-hydrated.
 11. Themethod of claim 1, in which the thixotropic cement slurry comprisessodium meta-silicate in an amount ranging from 0.5 weight percent to 3weight percent of cement pre-hydrated.
 12. The method of claim 1, inwhich the plug has a maximum volume calculated by dividing a volume ofthe conduit by a factor of 0.7.
 13. The method of claim 1, in which theouter diameter of the conduit is equal to a diameter of the wellboredivided by 2.25.
 14. The method of claim 1, in which the diameters ofthe conduit vary along a length of the conduit.
 15. The method of claim1, further comprising inserting the conduit to a specified depth at orabove a loss zone.
 16. The method of claim 1, further comprising pumpinga spacer fluid through the conduit prior to pumping the thixotropiccement slurry.
 17. The method of claim 1, further comprising pumping aspacer fluid through the conduit following the thixotropic cementslurry.
 18. The method of claim 1, further comprising pumping thethixotropic cement slurry through the conduit and pumping a drilling mudthrough the conduit.
 19. The method of claim 1, further comprisingremoving the conduit while pumping at least one of the thixotropiccement slurry, the drilling mud, or the spacer fluid through the conduituntil the second end of the conduit is above the plug.
 20. The method ofclaim 1, further comprising pumping the drilling mud down the wellboreoutside the conduit such that the drilling mud flows up the conduit.